When pumping from a hydrocarbon producing well containing gas and liquid it is known to be desirable to separate the gas from the liquid in order for the pump to operate effectively. Known gas separators have various deficiencies such that gas interference, resultant gas-locking, and potential resultant damages to downhole pumping equipment, as well as downtime and deferred production is an ongoing problem.
Most horizontal wells are completed with 5.5 inch and sometimes 4.5 inch production casing strings in all current domestic gas and oil plays. This leaves roughly 4.00 to 4.75 inches to convey and operate any form of artificial lift (AL) and gas separator. There are numerous gas separation techniques used for each form of AL, but most are moderately successful at best and some do a very poor job, but may be the only option.
For reciprocating rod pump the most common form of separation is the modified poor boy gas separator. A representative diagram is attached as FIG. 1.
For electrical submersible pumps (ESP's) the most common form of gas separation in horizontal wells is the rotary gas separator. This allows the pump to expel a reasonable volume of gas to the annulus after being ingested at the intake of the pump by way of centrifugal farce. One example is disclosed in U.S. Pat. No. 4,981,175 by Conoco Inc.
For progressive cavity pumps (PCP's) the most common form of gas separation is to run either an orienting intake sub which orients the intake: ports of the tailpipe to the lowermost portion of the wellbore aiming to avoid gas intake. Also, there is a diversion type separator which redirects the flow of gas and fluids up and around the pump then dumps the fluids annularly down to the intake while the gas travels upward to the surface. One example is disclosed in U.S. Pat. No. 7,270,178 by Baker Hughes Incorporated.
The 3 AL forms listed above are 3 of the 5 most popular and widely used forms of AL in all oil and gas wells completed today. The other two are gas lift and jet pump.
The most effective form of separation in horizontal wells has come by way of a sump or an extended section off the primary production casing that is drilled post completion, often at a tangent in the curves build section typically at 30 to 60 degrees, allowing for fluids to fall to a pump set below and allowing gas to break and travel upward. This is a costly method of separation due to added drilling and completion costs and there are risks involved such as wellbore stability and integrity issues, possibility to have issues running tools into the lateral, etc.
Additional examples of gas separators are described in U.S. Pat. Nos. 6,932,160 by Murray et al, 7,055,595 by Mack et al, 4,676,308 by Chow et al, and 2,883,940 by Gibson et al. Known gas separator devices can typically have limited effectiveness while occupying large amounts of space within the interior diameter of the well casing such that insertion and removal from the well casing may be awkward and difficult, and/or limited access is provided for other downhole tools if desired.